Several state legislatures within the PJM footprint are considering bills that would mandate public utilities report every vote they cast at the RTO, with some also requiring a description of how those actions would benefit ratepayers.
Maryland Del. Lorig Charkoudian (D) said she believes there is widespread interest in expanding transparency as capacity costs sharply increase and PJM proposes major transmission expansions and costly reliability-must-run (RMR) agreements with generation owners. Charkoudian has proposed legislation in the past three sessions that would require public utilities to submit annual reports detailing their votes.
Charkoudian said when utilities that are granted a monopoly in exchange for acting in the public interest are voting on those topics at PJM, it is imperative that state legislators and regulators have insight to ensure they are upholding their end of the deal.
“I think that for a very long time, most people’s eyes would glaze over when you talked about PJM. It is legitimately hard enough to understand energy policy in the state … and also talking about an RTO with 13 states and a governance process that as far as I can tell is purposely obfuscated,” she said. “I’ve spent a lot of time trying to figure out how we engage … given that PJM acts as a shadow government.”
By requiring that utilities report to the Public Service Commission, Charkoudian said the legislation avoids the jurisdictional issues that would come with trying to put requirements on a federally regulated RTO.
Exelon argued that the legislation could conflict with FERC jurisdiction over PJM and cause administrative burdens, given that PJM holds more than 400 stakeholder meetings annually.
In an announcement of his co-sponsorship of HB-782, Pennsylvania Rep. Christopher Rabb (D) said PJM’s practice of not recording votes taken at its lower committees — those outside of the Markets and Reliability and Members committees — can allow damaging policies to advance before voting becomes public. The legislation would require utilities to disclose their votes to the Public Utility Commission with a description of how that action is in the public interest.
“Decisions by PJM and its members (the utilities) directly impact our commonwealth’s transition to clean energy and the cost of electricity. Allowing these secret votes with no accountability is akin to the fox guarding the hen house,” Rabb said. “The people have a right to know about the decisions that are being made behind closed doors — especially as those decisions impact our policies and people’s paychecks.”
RTO spokesperson Dan Lockwood said “PJM disagrees completely with this assessment and operates an open and transparent stakeholder process.”
He pointed to a fact sheet detailing PJM’s stakeholder process, including how votes taken at the Members Committee are recorded and minutes are taken at all meetings. Aggregated results are posted for lower committees, while task forces and working groups may take nonbinding polls.
In comments on a FERC investigation, PJM said there are several pathways to bolster the ability for large consumers to benefit from co-locating with generators.
“What PJM and the industry need now is commission guidance on a path forward based on the record developed in this proceeding,” the RTO wrote in its March 24 response to the investigation into whether the RTO’s tariff can accommodate co-location without compromising reliability or consumer rates (EL25-49).
The investigation was opened in February after FERC rejected an agreement between Amazon Web Services and Talen Energy to expand a data center co-located with the Susquehanna nuclear plant in Pennsylvania, by modifying the generator’s interconnection service agreement to reduce its output to PJM. (See FERC Launches Rulemaking on Thorny Issues Involving Data Center Co-location.)
PJM’s comments laid out three approaches to co-locating load already permissible under the tariff and outlined five more that could be developed to recognize more possible configurations or limitations imposed by state laws.
The existing options cover arrangements where the load is co-located but not sharing a point of interconnection (POI) with the generator; shared POIs where the load is metered separately from the generator; and behind the meter (BTM) generation.
For data centers and the sorts of large consumers now pursuing co-location, PJM said the first two options are preferable because of the high reliability they carry, with the generation retaining its capacity status and the load paying for ancillary service and network integration transmission service (NITS) charges.
Having the load in front of the generator’s meter avoids relying on protective schemes that could fail; provides the consumer with more stable service; makes any curtailment management simpler to implement; and allows for more “comprehensive and holistic” system planning, PJM argued.
The BTM approach was designed for smaller loads with a proportional amount of on-site generation, which is capped by the tariff. Due to the inability to ensure reserves to cover the BTM resource, it can’t be given capacity status, and the load must procure capacity and NITS equal to its net consumption during coincident peaks.
Options 4 and 5 could apply to configurations where the load is behind a protective mechanism to prevent the consumer from drawing energy from the grid if the generator goes offline. The latter also allows the load to request permission to use PJM’s system as a backup.
The two are the only options that allow co-located load to avoid being designated PJM network load and allocated NITS and capacity costs. Ancillary service charges still would apply on the grounds that the generator benefits from network characteristics such as regulation, black start and reactive capability that inherently pass through to the load.
The generator also would be assigned any network upgrade costs associated with its output being reduced. Both are considered “less preferred” by PJM due to the risk of the protective schemes misoperating, causing the load to receive energy from the grid. PJM wrote that there was an event in November 2023 during which Susquehanna had an unplanned outage, and the load appears to have remained online and taken service from the grid.
Requiring ancillary service charges for co-located load was a sticking point for stakeholders considering several proposals for revising the RTO’s rules in 2023, along with jurisdictional questions about whether the load receives wholesale or retail energy.
The Markets and Reliability Committee ultimately rejected an Exelon-sponsored proposal that would have metered the generator and load separately, while allowing the generator to offer its full accredited capacity to PJM and requiring the load to pay for a capacity commitment through load serving entity charges. (See “Proposed Rules for Generation with Co-located Load Rejected,” PJM MRC Briefs: Oct. 25, 2023.)
“Ancillary services pass through transmission lines, not the air. Therefore, cost causation principles appear to support allocating co-located arrangements ancillary service costs (at a minimum),” PJM wrote. “Further, simple netting may not capture the costs ‘caused’ by co-located data center arrangements. Indeed, it is possible that such arrangements (depending on how they are structured) could avoid all costs because they would always net to zero (meaning the entire data center load is supplied by the co-located generator).”
Option 6 seeks to incentivize large loads coming onto the grid to bring their own generation by expediting interconnection studies for co-located resources. The generation still would be responsible for its own interconnection costs, and the load would be allocated NITS, energy and capacity charges.
Option 7 would allow co-located load to reduce its capacity obligation by committing to curtailing when requested by PJM in advance of anticipated emergency procedures. The load would not be included in the load forecast, and it would receive less priority to service from PJM, while the generator would be able to offer its capacity to PJM.
Building on existing demand response rules, Option 8 envisions changes to federal and state environmental rules around backup generation to allow the load to remain online when the co-located generator is required to serve PJM load by expanding the number of hours that reciprocating internal combustion engines can operate.
While broad changes to the capacity market design are not necessary in PJM’s perspective, it said some configurations might require new exceptions to the requirement that capacity resources offer into the energy market. Non-network load cannot be supplied by committed capacity, so for a resource holding a commitment to be dedicated to co-located load, it would need to request for its capacity status to be revoked. That process requires either a FERC order or approval from PJM and the Independent Market Monitor following a determination there would be no market power implications.
“Simply put, absent commission guidance to the contrary and PJM authorization, PJM cannot be in competition with non-capacity backed co-located loads for the output of a capacity resource. PJM cannot be simultaneously responsible for ensuring the energy needs of the PJM region and unsure whether a capacity resource will decide to serve PJM loads or co-located loads. Sellers should not be afforded the economic choice of following through on capacity commitments or incurring capacity resource deficiency charges and/or non-performance charges,” PJM wrote.
Jurisdictional questions also remain, with PJM arguing that some states grant exclusive franchises to public utilities that could prevent co-located load from accepting service from any entity other than the local utility. In some cases, there could be a regulatory gap where FERC does not hold jurisdiction over non-wholesale electric sales and states only regulate transactions where a sale is to the public. The comments noted the residual nature of the RTO’s capacity market and said there’s an opportunity to explore how bilateral transactions could fit into the co-location paradigm.
“State law regulatory particulars may, in certain instances, determine whether particular co-location arrangements will be regulated by the states or permitted by states with a franchised public utility model. As such, the propriety of the co-location arrangements proposed … are subject to different state law requirements that could disqualify certain options,” PJM wrote.
A three-judge panel of the D.C. Circuit Court of Appeals on March 28 rejected a challenge to FERC’s decision approving a pair of pipelines being built mainly to supply a proposed LNG export facility in Louisiana.
Healthy Gulf and the Sierra Club challenged FERC’s approval of Driftwood Pipeline’s application to build two new pipelines —lines 200 and 300 — in southwestern Louisiana (22-1226). The two pipelines would run alongside one another for 30 miles connecting an existing pipeline system in the north to the Lake Charles gas market.
Part of the project would run alongside another Driftwood pipeline called the Mainline, and both pipeline systems would serve Driftwood LNG.
FERC did an environmental impact statement for the project under the National Environmental Policy Act (NEPA), which acknowledged adverse environmental impacts but found none to be significant. The project was expected to increase greenhouse gas emissions, but FERC declined to characterize those emissions as significant.
The environmental groups argued that FERC should have done more to calculate what upstream impacts the pipelines would have by spurring development of new wells for natural gas.
“FERC adequately explained why it could not reasonably predict those two factors,” the court said. “As to the number of new wells, FERC concluded that it did not know ‘whether transported gas would come from new or existing production.’ And as to their location, FERC explained that the ‘specific source of natural gas to be transported via the project is currently unknown and would likely change throughout the project’s operation.’”
Executives from Driftwood’s parent company, Tellurian, have said gas for the Driftwood project would come from the Haynesville Shale in northern Louisiana, but at best, that means FERC could tell where some wells might be drilled, not their number, the court said.
The fact that the 200 and 300 lines are secondary to the Mainline project also complicates figuring what sources of gas will flow through them. Driftwood testified that it expects the pipelines will just bring existing gas to its LNG facility.
The environmentalists argued FERC could use the social cost of carbon to calculate the impacts of greenhouse gas emissions from the projects. FERC said it was unaware of any scientific method that could assess the climate impacts of pollution associated with the specific pipelines.
The court agreed that FERC lacked a non-arbitrary way to determine when identified social costs become significant under NEPA.
The environmentalists also argued that FERC should have calculated the pipelines’ impact alongside that of the Driftwood LNG project, especially since they are planned to supply it with gas in its early day of operation, as the Mainline will be built later. But the petitioners failed to raise the issue before FERC, which means the court did not address it substantively.
The environmental groups also questioned the market need for the project under the Natural Gas Act, but the court agreed with FERC’s finding that the signed contracts for most of pipelines’ capacity was evidence enough. The two lines will also connect with different gas supplies than the Mainline, which offers the Driftwood LNG project some diversity in supply to export.
Electricity imports from Canada into New York have continued without any change to prices, but the “fluidity and uncertainty” of President Donald Trump’s trade policy make it difficult to predict anything, state agencies reported to Gov. Kathy Hochul in March.
“It is still unclear whether the tariffs are meant to include electricity sales,” the New York Department of Public Service, New York State Energy Research and Development Authority, and Division of Homeland Security and Emergency Services said in a joint analysis released March 19. “While the 10% energy tariff has been in place since March 4, and energy imports have continued unchanged since they took effect, the tariffs have not yet appeared on invoices from suppliers.”
However, while “impossible to accurately forecast at this time,” it is expected that Trump’s threatened tariffs on non-energy products, such as steel and aluminum, would impact the supply chains for transmission and distribution facilities, generators and other utility infrastructure investments.
Trump imposed a 10% tariff on energy imports March 4, and additional, “retaliatory” tariffs — in response to Canada’s own tariffs — on vehicles and automotive parts will begin April 2. (See Ford Suspends Ontario Electricity Tariff as Trump Wavers.)
“While the fluidity of this situation makes it difficult to forecast the precise energy cost impacts of the tariffs, we have concluded that the potential cost impacts would not be material in the short term, but due to extensive variables outside our control, the tariffs could have significant affordability impacts in the long term,” the agencies wrote.
Electricity costs could increase by $42 million to $105 million annually, while natural gas could increase by up to $4.4 million. The agencies based this assessment on a review by NYISO of historical imports and their own review of trade patterns.
Liberty Gas — which services Franklin, Lewis and St. Lawrence counties, all along the Canadian border — is “heavily reliant” on imports for its roughly 14,600 residential household customers, 1,700 commercial and 21 industrial customers, according to the report. Two co-generation plants in the North Country region also depend on imports.
The analysis also notes that about 5,400 customers in Plattsburgh receive their gas directly from Canada, and no pipelines connect the city to the state’s gas network. If imports become unavailable, the report says the local utilities in the North Country lack the specialized equipment needed to accept truck deliveries of compressed or liquefied natural gas.
In the most extreme case, if Canada were to halt electric exports during peak summer months, “it could create reliability challenges” and retired natural gas plants could be called back into service, it says.
Connor Waldoch, founder of Grid Status and former senior associate with the NYISO Market Monitoring Unit, told RTO Insider he suspected the impact to electricity costs could be higher than the agencies estimate.
“I suspect that in real-world conditions, the tariff could incur costs greater than the $105 million high end of the range,” Waldoch said. “This is both from the direct imports side … as well as the potential increase in fuel costs for marginal units.”
He noted the agencies were working under an extremely short timeline to produce the analysis in an environment of considerable complexity. Hochul, along with U.S. Sen. Chuck Schumer, had requested the report March 10.
Kajal Lahiri, distinguished professor of economics at State University of New York at Albany, said that under the best of circumstances, economic forecasts are uncertain and include confidence intervals; this is not the best of circumstances.
“The issue right now is the market is so fragile, so uncertain as to where this is going,” Lahiri said. “What is Trump going to do? What’s really in his head?”
But regardless of what shape the tariffs take, “you know it’s going to hurt,” said Lahiri, outlining the numerous connections between the two countries. “There’s a huge business that takes place along those lines. Affecting them could mean pervasive effects on our society.”
FERC has approved filings by a pair of Massachusetts utilities establishing distribution fees for standalone electric energy storage systems (ESS) that connect to the distribution system but participate in ISO-NE wholesale markets (ER24-2795-001, ER24-2796-001.)
The filing comes in the wake of FERC Order 2222, which requires RTOs to eliminate obstacles for the participation of distributed energy resource aggregations in wholesale markets. FERC approved key aspects of ISO-NE’s compliance proposal for the order in 2023 (ER22-983-004). (See FERC Accepts ISO-NE Order 2222 Compliance Filing.)
The utilities, both subsidiaries of National Grid, wrote that ESS fees will be based on three rate components: an as-used peak demand charge; a contract demand charge; and an access charge, “reflecting different types of costs incurred by National Grid.”
The peak demand charge reflects “direct costs of owning and operating its distribution system.” The contract demand charge covers operations and maintenance expenses “for line transformers and meters, load dispatching, supervision and engineering, and allocated portions of labor-related overhead.” The access charge incorporates “costs incurred to provide WDS [wholesale distribution service] to specific customers.”
The Alliance for Climate Transition (ACT, previously named the Northeast Clean Energy Council) and the Massachusetts Attorney General’s Office (AGO) filed concerns about National Grid’s proposal.
ACT made the case that the distribution fees should not apply “when an energy storage system is providing ancillary services in response to ISO-NE dispatch instructions.”
The trade group wrote that FERC Order 841 exempts storage systems from transmission delivery fees when they are dispatched to provide ancillary services, and said the commission “should apply that same policy rationale to the corresponding issue of distribution charges.”
The group also asked FERC to remove or revise the proposed definition of distributed energy resource management systems (DERMS), writing that “the technology is not yet utilized on the company’s system,” and the timeline for implementation is unclear.
It also expressed concern that additional provisions in the proposed wholesale distribution tariffs (WDTs) would result in double charging distribution costs to ESS customers. ACT also opposed language directing ESS customers to be disconnected automatically if actual demand exceeds the contract demand value.
Meanwhile, the AGO requested that National Grid update its filing to account for the effects of recent orders by the Massachusetts Department of Public Utilities on National Grid’s state-jurisdictional wholesale distribution service rate calculations. The AGO asked National Grid to submit the orders to FERC with underlying data to support the calculations.
Responding to the protests, National Grid updated its filing to comply with the AGO’s request and removed the automatic disconnection provision highlighted by ACT.
National Grid defended its definition of DERMS in the tariffs, writing that it is “actively implementing DERMS through its ongoing grid modernization efforts and related pilot programs,” and that it will only use DERMS “when such product is a company standard offer and operational at the customer site.”
The company opposed ACT’s request to exempt ESS discharging for ancillary services from distribution fees.
“The impact of ESS imports and exports for ancillary services on the distribution system is the same as any other load or exports and loads exceeding system parameters can result in exceedance of system capacity,” National Grid wrote. “It is appropriate and necessary for ESS to pay for the use of the distribution system to provide ancillary services to ISO-NE.”
On March 28, FERC approved National Grid’s updated filing, writing that the changes to the utilities’ WDTs “are a just and reasonable rate design that allows ESS connected to the distribution system to participate in wholesale markets,” adding that the “rates reasonably reflect the costs of serving these customers.”
The commission wrote the changes made and additional evidence and clarifications provided by National Grid “address the concerns raised by the protesting parties.”
FERC agreed with National Grid’s argument that ESS discharging for ISO-NE ancillary services should not be subject to distribution fees.
“While the commission found it appropriate to exempt electric storage resources from transmission charges when they are dispatched to provide a wholesale service, the commission made no such finding with respect to wholesale distribution charges,” FERC wrote.
FERC directed National Grid to submit the effective date for the changes “no less than seven days prior to the date that the filing parties implement the proposed WDTs.”
Stakeholders Approve Protocol Changes for Real-time Co-optimization
AUSTIN, Texas — ERCOT stakeholders endorsed several protocol changes related to the ISO’s real-time co-optimization project, keeping on track a project seen as a cornerstone for future market improvements.
Alluding to the ongoing college basketball tournaments, ERCOT’s Matt Mereness, chair of the Real-time Co-optimization and Battery Task Force (RTC+B), portrayed the protocol changes as “the road to the Final Four.” Their approval sets them up for the Board of Directors’ consideration during its April 7-8 meeting, with the goal of beginning full market trials of the software and systems May 5.
“We’re six weeks out on the first set of [market] trials starting,” Mereness told members of the Technical Advisory Committee (TAC). “Today’s approval sets the stage for more approvals and people so that we can develop the code and parameters to dial those in for our market trials. That’s the gist of it.”
The key nodal protocol revision request (NPRR1269) determines and codifies policy changes that were deferred from the original RTC-related protocols developed after the project’s inception in 2019: ramping scaling factor values, ancillary service (AS) proxy offer floor parameters, and ancillary service demand curves’ (ASDC) use in reliability unit commitment (RUC) studies.
Two other NPRRs were placed on TAC’s combination ballot, essentially a consent agenda. NPRR1268 makes changes to the ASDC as modified by the Independent Market Monitor. NPRR1270 clarifies the removal of automatic ancillary service qualification and adds details for qualifying resources that provide the services in real time.
Much of the debate during the stakeholder process centered on the proxy offer floors. ERCOT initially proposed a $0 offer floor, which was supported by the IMM, but the RTC task force pushed for a $2,000 floor. A compromise eventually was reached on the minimum of a $2,000 floor or 95% of the ASDC.
The demand curves’ use in RUC studies was another “evolving discussion,” as Mereness put it, in determining the appropriate price signals within the study tool to drive efficient commitments. The Protocol Revision Subcommittee sent NPRR1269 to TAC with its approval of the ASDC compromise, a $15 RUC ASDC floor, and a $15 floor for real-time and day-ahead market ASDCs.
TAC approved NPRR1269 22-7 with one abstention. All six members of the consumer segment opposed the measure. They were joined by AP Gas & Electric, an independent retailer in Houston. In filed comments, the consumer interests asked the ERCOT board to “exercise judicious restraint before considering” the policy change.
“There is no real harm to waiting for [RTC] to be implemented before making such a fundamental shift in its design,” they wrote. “Frankly, consumers would prefer a future where ERCOT had to justify a RUC decision in a situation like this instead of a permanent structural change in the market to avoid the possibility of hypothetical RUCs.”
“Our concern is with the underlying approach. As to why you would institute a floor without evidence that it will resolve something, we would just generally be uncomfortable with unnecessarily intervening in market outcomes,” Eric Goff said during the TAC discussion. “You have to acknowledge that this is an administratively determined curve. In general, it’s appropriate for a curve to be able to indicate a lack of value, that something is demanded. That’s kind of one of the fundamental approaches that we see to the extent that the point of this is to alleviate some potential for RUCs.”
The IMM warned that the proposed ASDC floor for the day-ahead and real-time markets could result in more than $100 million in excess costs to consumers, saying the proposal is not supported by “economic fundamentals or empirical evidence.”
It said the proxy offer floor compromise “does not reflect a competitive offer and exposes consumers to unnecessary and excessive costs,” calling for an offer cap of no more than $15. The IMM also said the ASDC floor for RUC is not necessary for the commitment process to function properly when RTC goes live in December.
Large Load Task Force to Remove ‘Flexible’
The Large Flexible Load Task Force plans to return to TAC’s April 23 meeting with charter changes that rename the group by removing “flexible” from its title.
“We could never actually define flexible when the crypto miners, where this all started, came in,” explained the task force’s vice chair, Longhorn Power’s Bob Wittmeyer. “They said that they were flexible. By that, they meant they were flexible within settlement intervals. ERCOT interpreted that to mean within milliseconds, and there was some disconnect between those two things.”
The task force’s members also proposed the group be reclassified as a working group reporting to TAC, with a sub-group focused on data centers. TAC’s leadership was open to the suggestion.
“Task forces exist when the problem is envisioned to be short term and be solvable and go away,” Wittmeyer said. “Large loads certainly appear to be here to stay, and there are operational issues with city-size loads doing things. Anytime you have a city-size load, that can all react roughly at the same time, that’s a cause for concern.”
Staff told TAC that the large-load interconnection queue contains just over 99 GW in primarily standalone projects. ERCOT says it can confirm 4,616 MW have been energized.
Market Design Discussion Postponed
A scheduled discussion on a proposed new market design framework was put off until April’s TAC meeting because of March’s “weighty agenda,” said ERCOT’s Keith Collins, vice president of commercial markets.
CEO Pablo Vegas presented the framework to the board in 2024, saying the grid operator needs a structure that allows it to evaluate changes to the market design, relative to the attributes needed to reliably operate the grid. Staff presented the framework to TAC in October and received comments from stakeholders related to resource adequacy, initiative measurement and the structure’s alignment.
The framework’s pillars, as developed by staff, are to position ERCOT as an industry leader for reliability and resilience and to strengthen the footprint’s economic competitiveness. The grid operator says that while reliability is the organization’s primary objective, “costs should always be considered” as it seeks “market outcomes and solutions that result in the most competitive wholesale power rates and retail prices without compromising reliability or resilience.”
Large Load Modeling Requirements
The committee had to endorse NPRR1234 and its associated Planning Guide revision (PGRR115) twice when a desktop edit to the PGRR inadvertently created an unachievable compliance deadline, based on the measure’s anticipated approval date. Staff then conducted a triage of the NPRR to push the compliance dates out by two months.
The two changes establish interconnection and modeling requirements for large loads, defined as one or more facilities at a single site with an aggregate peak power demand of 75 MW or more. TAC unanimously endorsed both measures. Three members of the consumer and independent generator segments abstained from the PGRR.
The committee approved the combination ballot that included four NPRRs, one PGRR, a system change request (SCR) and revisions to the Nodal Operating (NOGRR) and Settlement Metering Operating Guides (SMOGRR) that, with board approval, will:
NPRR1256: Changes language in adjustment period and real-time operations protocols related to must-run alternatives (MRAs), primarily in grey-boxed language from NPRR885 (Must-Run Alternative Details and Revisions Resulting from PUCT Project No. 46369, Rulemaking Relating to Reliability Must-Run Service) to align the terminology for energy storage resources (ESRs) in the single-model era. It also specifies how qualified scheduling entities representing ESR MRAs would be settled for providing MRA service.
NPRR1268: Define the methodology for disaggregating the operating reserve demand curve into blended ancillary service demand curves.
NPRR1270: Update requirements for load resources that are changing under RTC and were not updated in earlier revisions; remove language associated with group assignments in the day-ahead market; eliminate the automatic qualification of all resources to provide on-line non-spinning reserve and SCED-dispatchable ERCOT contingency reserve service, among other changes. Resources will be required to undergo a qualification test to provide each of these services.
NPRR1273: Modify ESRs’ capacity to the amount sustained for 45 minutes included in the physical responsive capability’s calculation.
NOGRR274: Conforms the guide to NPRR1217’s (Remove Verbal Dispatch Instruction Requirement for Deployment and Recall of Load Resources and Emergency Response Service Resources) protocol changes.
PGRR119: Codify that a reliability margin will be used when limits associated with a stability constraint are modeled in the Regional Transmission Plan’s reliability and economic base cases.
SCR829: Add an application programming interface to upload and download unit testing data from the net dependable capability and reactive capability application.
SMOGRR028: Give guidance for allowing loss compensation for current limiting reactors.
The West-Wide Governance Pathways Initiative’s Launch Committee on March 28 said it hopes to seat a permanent board by either 2026 or 2027 for the regional organization (RO) that will govern CAISO’s Western energy markets.
Specifically, the Pathways Formation Committee is considering seating a permanent board by either July 2026 or April 2027 under Phase 2 of the group’s plan, which includes creating an RO that will oversee CAISO’s Western Energy Imbalance Market (WEIM) and Extended Day-Ahead Market (EDAM), according to a committee presentation.
Speaking during a monthly update call, Kathleen Staks, executive director of Western Freedom and the Launch Committee’s co-chair, said the committee is evaluating the dates and will provide a recommendation during the next stakeholder meeting April 26.
A seven-member interim board will be put in place in the meantime, because board members must be listed when corporate documents are filed with the Internal Revenue Service, according to the presentation.
Staks clarified that the interim board will have limited duties and that the Launch Committee will retain its decision-making role. Putting in place an interim board, instead of seating a permanent one this early in the development of the RO, also saves money, Staks said.
Launch Committee member Jim Shetler, general manager of the Balancing Authority of Northern California, said about $250,000 is needed to sustain the committee through October, when the so-called Pathways Legislation is expected to pass in the California legislature. (See Pathways ‘Step 2’ Bill Sets Conditions for EDAM Governance.)
Shetler said he’s “comfortable” there’s enough money “to get us through October.”
“The issue will be post-October, … we’re looking at a couple options around when do we seat the permanent board, and the timing around that will obviously impact how much money we need. So, we’re still refining those numbers,” he said.
Shetler expects a budget within the next 30 to 60 days, “with a goal of trying to get commitments in place starting in October, November of this year to fund the remaining efforts on this Pathways Initiative.”
Pathways received a commitment of nearly $1 million from the DOE under former President Joe Biden’s administration in November to underwrite the committee’s efforts to establish an RO to oversee CAISO’s WEIM and EDAM.
The award was issued through the Pathways Initiative’s philanthropy adviser, Global Impact, which the group’s Launch Committee partnered with earlier in 2024 to secure outside funding for its operations, which so far have been supported by donations — and volunteered staff — from its participants.
President Donald Trump’s administration on Jan. 27 paused all federal grants and loans, according to a memo issued by the White House’s Office of Management and Budget.
As attendees fussed over their last morsels of breakfast, Emilie Nelson, COO of NYISO, opened the Independent Power Producers of New York Spring Clean Energy Conference with a keynote addressing the strange situation New York’s grid is in, and the need to continue to deliver reliability despite political uncertainty.
“Since the ISO’s inception in 1999, system reliability has been our top priority in the face of great change,” Nelson said. “We maintain that focus [through] societal changes, policy-based or technical issues, or being prepared to manage more frequent, extreme weather.”
Speaking of changes, Nelson was a last-minute substitution for NYISO CEO Rich Dewey, who was called away on short notice to testify before Congress. (See All 7 ISO/RTOs Send Senior Executives to Update Congress on Reliability.) Nelson touched on themes that probably were familiar to the audience: the tension between policy pushes for zero-emission generation, the aging grid, increasing customer costs and concerns about winter peaking.
“It is imperative that during this time of rapid change, … we maintain adequate supply necessary to meet growing consumer demand for electricity,” she said. “Competitive markets continue to provide the most powerful vehicle to speed investment in the grid.”
The message to independent power generators was not lost: The ISO needs them to continue to build more generators to replace retiring infrastructure.
Nelson said building effective wholesale markets has helped facilitate the grid’s transition, reduce power costs and protect ratepayers from development cost risks. Building the market to support future reliability was her “North Star,” she said.
How Things Have Changed
The address kicked off a day of discussion about navigating these treacherous waters. Concern about Donald Trump and Elon Musk’s disruptions came up repeatedly in panel discussions.
“The new administration feels like they’ve been in place for years even though it’s only been 65 days,” Todd Snitchler, CEO of Electric Supply Power Association, said during a morning panel discussion. “Across virtually all of the administrative agencies that impact our work, from FERC to DOE, to SEC to CFTC, all the places that touch the work we do are seeing some sort of disruption.”
Snitchler said some disruption was good and some was bad but all of it was confusing. He was unsure “what the goal” of the administration is.
At the same time, Snitchler said he observed a “tremendous” amount of state-level activity. Some states, like Ohio, are leaning into markets. Other states, like New Jersey, express doubts about the role of markets on the grid.
“New York is potentially in a spot where it needs a reminder about the value markets have provided and how customers have benefited,” he said.
From left: Marie French, POLITICO; Laura Chappelle of Potomac Law Group; IPPNY CEO Gavin Donohue; EPSA CEO Todd Snitchler; and NEPGA CEO Dan Dolan discuss regional challenges across control areas. | Timothy H. Raab and Northern Photo
Marie French, an energy reporter for POLITICO who moderated the panel, said she observed New York had slowed some of its climate initiatives. Some of that was due to the withering of federal support for offshore wind and other climate projects. Not all of the delays were because of Trump, in her estimation.
“They’re realizing that all of these things are more complicated to implement and a little more expensive than they had hoped,” French said.
IPPNY CEO Gavin Donohue remarked that until roughly six months ago, there had been a lot of conversation statewide about climate change, climate justice and carbon pricing. After the election, that conversation shifted abruptly.
IPPNY CEO Gavin Donohue | Timothy H. Raab and Northern Photo
“Everything has switched to be about reliability and affordability,” Donohue said. “With the economic development backdrop, we have data centers, chip fabs, just a new interest in economic development where we have to build a grid out to three to four times the size.”
Donohue said discussions about nuclear power also suddenly became prominent and that the state needs to build the market to attract all kinds of new generation technologies. He mentioned hydrogen and geothermal, which seem to have fallen out of the discussion, to his disappointment.
“Everything is going to collide, and we just need to be ready,” he said. “We need to make sure that we promote policies that are in the best interest of ratepayers and competitive markets.”
How Do You Build New Nuclear?
There’s renewed interest in building new nuclear power plants in New York. (See NY Takes a Closer Look at Advanced Nuclear.) Panelists said one key element is finding a community that wants a nuclear power plant.
Philip Church, Oswego County administrator, said that since 1969, the county has been home to the Nine Mile Point nuclear plant. The operator, Constellation, has been a good safety and economic partner, he added. “We’re the home of three nuclear power plants; 75% of New York’s nuclear plants are in our hometown.” If Church had his way, there would be a fourth nuclear unit in Oswego County.
Despite the optimism, the history of new nuclear in the U.S. is plagued with huge cost overruns and lengthy delays. The first new reactors built in the U.S. since 2016, Vogtle’s two units in Georgia went online seven years late and $17 billion over budget. (See NIA: Cost, Risk Sharing Needed to Grow Advanced Nuclear Pipeline.)
From left: Rich Barlette, Constellation Energy; Oswego County Administrator Phil Church; New York State Pipe Trades Association President Greg Lancette; Patrick White, Nuclear Innovation Alliance; and Marcus Nichol, Nuclear Energy Institute, discuss the challenges and opportunities posed by new nuclear power technologies. | Timothy H. Raab and Northern Photo
Patrick White of the Nuclear Innovation Alliance said new technologies are making nuclear power safer, more flexible and more appropriate for more locations. He cited small modular nuclear reactors, high-temperature gas reactors and sodium liquid metal reactors. Some of these are just smaller form factors of existing reactors, but others, like the liquid metal reactor, can generate enough heat to support a thermal energy battery.
“You start to see other options of how we can think differently about nuclear technology and how can it fit into a system to complement renewables,” White said.
ACE NY Executive Director Marguerite Wells | Timothy H. Raab and Northern Photo
At the same time, smaller reactors theoretically can help bring down construction costs and reduce safety concerns. If most of the components of a small reactor are built offsite and shipped to the building site, that can reduce costs. Smaller reactors run on less fuel and could be more easily contained.
While new technologies are often expensive, the panelists said this could be offset with federal, state or inter-company agreements to buy in, derisk and reduce construction costs for new technology.
“When you buy a piece of any other technology, you’re paying the average cost of what they’re able to produce it at,” White said. “Imagine how much more it would cost to buy an iPhone if you had to pay for the first iPhone’s development costs, the factory, the shipping, the supply chain, upfront.”
The panelists said co-purchasing between four to six units could hit “the sweet spot” to reduce the cost of an individual reactor.
IPPNY Study: Competitive Generation Reduces Costs
At the final event of the conference, IPPNY unveiled a study commissioned by the New York Affordable Clean Power Alliance about the impact of competitive markets on the cost of electricity. The Alliance is a new group formed out of IPPNY, the Alliance for Clean Energy New York, the New York Battery and Energy Storage Technology Consortium, and other renewable energy organizations.
Multiple Intervenors, a consortium of large industrial interests and large electrical consumers, issued a press release shortly after the conference, supporting the study.
“This report affirms Multiple Intervenors’ position that private investment in power generation results in lower electricity costs, greater reliability and improved environmental performance,” said Michael Mager of Multiple Intervenors. “Returning to utility-owned generation would only increase financial burdens on businesses already navigating challenging economic conditions.”
“Nearly 30 years ago, the New York PSC adopted a set of principals … starting with the premise that competition in the electric power industry will further [the] economic and environmental well-being of New York state,” said Shannon Maher Banaga, senior managing director of FTI Consulting, the study authors. “That premise holds true today.”
Members of FTI Consulting walked through their findings. After the introduction of a competitive generation market, the state’s electricity prices dropped steadily over the past 30 years. Meanwhile, the price of delivery increased steadily.
“If you compare the past five years of data to the five years prior to restructuring, total generation costs since are roughly 35% lower,” said Robert Kaineg, managing director of FTI. “But those of us that have been watching the news and are sensitive to these issues know that has not translated into lower bills for customers.”
Robert Kaineg, FTI Consulting Communications | Timothy H. Raab and Northern Photo
Kaineg said he found the costs of transmission and distribution had risen over time and that state policies supporting energy efficiency and clean energy further escalated costs.
“We’ve seen this come to a head recently with an announcement by Con Ed that it was going to increase its rates by 11.4%, but that buried the lead because they were raising delivery rates by more than 19%,” Kaineg said.
Kaineg added that private developers were less expensive in almost every case than utilities. Utilities faced all the same challenges that private developers did, and since restructuring, they didn’t necessarily have any in-house generation-building expertise.
“There really isn’t a reason to expect, from a cost or development perspective, that utilities are going to enjoy any advantages in asset development,” he said.
IPPNY’s Donohue said some of the increases in transmission and distribution costs fell on an overall lack of investment in the basic necessities of energy infrastructure.
“We have avoided making tough decisions on transmission and generation,” Donohue said. “When you wait 10 years to put a new line in, it’s obviously going to be a lot more expensive than it was 10 years earlier.”
ACE NY Executive Director Marguerite Wells said everyone expects more of the power system now than 50 years ago. More things are electronic; more things require electricity to work.
“We have to pay the piper to do stuff that’s been deferred for a long time,” Wells said. “But the truth of the matter is that it has nothing to do with the source of the electricity and … everything to do with serving the needs that people want from their power system.”
PROVIDENCE — Speakers at the ISO-NE Consumer Liaison Group on March 27 discussed the system-wide costs and emissions benefits of energy efficiency and demand flexibility and called on policymakers to double down on efficiency programs as energy demand grows.
State energy efficiency programs have faced some political scrutiny in recent months amid high winter energy costs. To help reduce near-term electricity costs, the Massachusetts Department of Public Utilities in late February directed utilities to shave $500 million off the upcoming three-year plan for the Mass Save energy efficiency program.
Jamie Dickerson, senior director of climate and clean energy programs at the Acadia Center, said energy efficiency is responsible for a roughly 15% reduction in the region’s overall power demand and has brought more than $55 billion in benefits to the region since 2012.
He said it’s unfortunate energy efficiency “has emerged as a scapegoat for some,” given the cost reductions it can provide. Moving ahead, he emphasized the importance of energy efficiency as peak loads increase and estimated that achieving 20% demand flexibility in winter could save the region about $8 billion in transmission spending by 2050.
“Let’s face it: In every possible way, negawatts — with an ‘N’ — are better than megawatts with an ‘M,’” said New Hampshire Consumer Advocate Don Kreis.
However, Kreis said it can be difficult to convince ratepayers they’re benefiting from energy efficiency programs when they may not receive the actual upgrades incentivized by the programs.
David Westman of the Vermont Energy Investment Corp. (VEIC), the administrator of Vermont’s energy efficiency programs, said demand reductions — especially at peak times — provide cost and emissions benefits to the entire system.
He highlighted how Vermont has helped ski resorts improve the efficiency of their snowmaking operations and said state incentives reducing the payback period for high-efficiency snow guns are a key component to convincing resorts to adopt more efficient equipment.
At Stratton Mountain in Southern Vermont, replacing 403 snow guns has enabled a 17% reduction in seasonal kWh demand and a 40% reduction in demand during the most essential peak winter hours.
He noted that VEIC operates an energy efficiency resource participating in ISO-NE’s forward capacity market (FCM), with about 116 MW of summer capacity and 156 MW of winter capacity. The resource’s participation in the FMC has generated over $80 million in revenue since 2010, all of which is invested back into energy efficiency efforts.
Westman praised ISO-NE’s commitment to keeping energy efficiency in its capacity market as it undergoes a major market reform effort. He said PJM’s move in 2024 to make energy efficiency resources ineligible for its capacity market “puts a lot of PJM ratepayers at a significant risk of higher costs.” (See PJM Asks FERC to Eliminate Energy Efficiency from Capacity Market.)
Brett Feldman, energy efficiency manager for Rhode Island Energy, acknowledged that many of the easiest energy efficiency reductions already have been achieved, with LED lighting “basically baseline now.”
However, he said there still is a lot of home retrofit work to be done as homes electrify and said it’s important to focus on electrification whenever possible with new homes. He noted that artificial intelligence tools could help provide more gains.
The flip side of artificial intelligence is significantly increased energy demand from data centers, and several speakers expressed concern that data center demand growth may wipe out some of the gains made by energy efficiency.
“AI specialized data centers are likely to represent the single largest driver of load growth in the U.S. over the next five to 10 years,” said Tyler Norris, a Ph.D. student at Duke University who is focused on power systems.
He recently authored a study that found that, because the U.S. power system is built to meet infrequent peak loads, existing headroom on the grid “is sufficient to accommodate significant constant new loads, provided such loads can be safely scaled back during some hours of the year.”
The study found ISO-NE has the capacity to add 4.3 GW of new demand with just 1% curtailment, or 3.5 GW with just 0.5% curtailment.
Pacific Gas and Electric will meet some of this year’s summer electricity demand in California through a virtual power plant demonstration project that will include as many as 1,900 residential customers.
And in another recent announcement, PG&E said it will award up to $43 million for nine microgrid projects in Northern and Central California. The money, distributed through the company’s Microgrid Incentive Program, will fund the development of community microgrids in disadvantaged areas.
PG&E described its virtual power plant program, known as Seasonal Aggregation of Versatile Energy (SAVE), as a peak load shifting and shaping program.
It will recruit up to 1,500 residential electric customers with battery energy storage systems and about 400 customers with smart electric panels. The VPP will be dispatched from June through October for up to 100 hours.
Program participants will be concentrated in California’s Central Valley and the south San Francisco Bay Area.
PG&E is partnering on its VPP demonstration with Sunrun, a company that sells residential solar-plus-storage systems.
Using Tesla’s grid services platform, Sunrun will optimize Powerwall batteries to provide a precise amount of power at specific times to certain locations. For non-Tesla batteries, Sunrun will use Lunar Energy’s Gridshare platform.
Sunrun will manage participating customers’ battery dispatches while making sure participants have at least 20% of their battery capacity in reserve in case of power outages.
“Customers with home batteries are a solution to alleviating strain on our electric grid,” Sunrun CEO Mary Powell said in a release.
Smart Panel Participants
Residents with smart electric panels will participate in the VPP program through a partnership between PG&E and grid service provider SPAN, which will shape home energy demand during peak events.
Customers will be able to set preferences on an app so they can use certain appliances during peak hours while still reducing grid congestion.
PG&E said it chose places to deploy the VPP program based on:
the potential for overloading during peak summer hours;
participating aggregators’ concentration of customers; and
ability to test performance across varying load shapes.
About 60% of SAVE participants will be in low-income or disadvantaged communities.
PG&E is conducting the VPP demonstration project as part of California’s Electric Program Investment Charge (EPIC) initiative. Funded by utility customers, EPIC invests in research that may help the electricity sector meet the state’s energy and climate goals.
Microgrid Grants
In a separate program, PG&E announced $43 million in funding for nine microgrids in communities deemed vulnerable to power outages.
The microgrids, which can be disconnected from the grid and provide energy during an outage, typically serve homes and essential facilities such as hospitals, police and fire stations, food markets, and water treatment plants.
PG&E selected the nine projects from a pool of about 50 inquiries. The projects are in California’s North Coast and North Bay areas. Four will serve tribal communities.
Generation resources in microgrid projects may include solar, battery storage, pumped hydroelectric storage, small hydroelectric and biomass.
PG&E is planning a second round of Microgrid Incentive Program grants and will accept applications from April 3 through May 30.
